Summary This paper describes a multistep pseudofunction-generation process designed to incorporate several scales of process designed to incorporate several scales of heterogeneities into one set of final pseudofunctions to be used in large gridblocks for field simulations. A detailed description of the multistep scale-up process is provided. The calculational procedure and the results of an extensive numerical scaling-up experiment from Kyte and Berry pseudofunctions are described. Three geological descriptions involving pseudofunctions are described. Three geological descriptions involving random permeability variations are used. The effect of three scales (sizes) of heterogeneities on a standard oil/water relative permeability curve is determined from a three-step pseudofunction-generation process. Ranges of mobility ratios, viscosity/gravity ratios, and viscosity/capillary ratios are used in the displacements to provide a guide to the effect of various types and scales of heterogeneities on fluid flow in several regimes. Introduction Pseudorelative permeabilities and capillary pressures have been used Pseudorelative permeabilities and capillary pressures have been used for several years in reservoir simulations to reduce the number of dimensions of the flow field or to reduce the total number of gridblocks (to a computationally economical number). The process allows us to replace the geologically detailed fine grid of rock (laboratory) relative permeability and capillary pressure curves wita few large homogeneous gridblocks containing an effective permeability and pseudofunctions. When the displacement is permeability and pseudofunctions. When the displacement is simulated with the coarse grid of effective permeabilities and the generated pseudofunctions (relative permeability and capillary pressure), the pseudofunctions (relative permeability and capillary pressure), the fluid flow across the coarse-grid boundaries or into the production wells will be the same as in the fine-grid simulation. Thus, the effect of increased numerical dispersion and the decreased detail of the reservoir description in the coarse grid are overcome by the pseudofunctions. pseudofunctions. Recent trends in reservoir-description research have been directed at replacing a fine-grid reservoir containing a specific type of heterogeneity with a very coarse (homogeneous) grid. Davies and Haldorsen replaced stochastic discontinuous shale bodies with pseudorelative permeabilities. Pande et al. studied the pseudorelative permeabilities. Pande et al. studied the replacement of a noncommunicating layered system with a 1D description of the layered system by determining the appropriate pseudofunctions. Both works consider one scale of heterogeneity pseudofunctions. Both works consider one scale of heterogeneity e. g., the discontinuous shales or the noncommunicating layers. Their implicit assumption was that smaller scales of heterogeneities (e.g., variations in the rock permeability between the shales or within the layers) were not important and that the rock curves could be used in the fine gridblocks. Lasseter et al. extended the classic concept for the use of pseudofunctions in heterogeneous reservoir description. The idea water pseudofunctions in heterogeneous reservoir description. The idea water use pseudofunctions in a multistep process to account for several scales of rock heterogeneity and, at the same time, to control numerical dispersion. The process begins with laboratory rock relative permeabilities and capillary pressures at the small scale and permeabilities and capillary pressures at the small scale and ends up, after several steps, with final pseudofunctions for large gridblocks designed for use in field-scale simulations. These final pseudofunctions control numerical dispersion as do the standard pseudofunctions control numerical dispersion as do the standard one-step pseudofunctions, but they also account for the several scales of reservoir heterogeneities. A detailed explanation of the scalingup process follows in a later section. The research project associated with this paper (see Acknowledgment) is meant to expand the work of Lasseter et al. and to provide an understanding of the effect of various scales of heterogeneity provide an understanding of the effect of various scales of heterogeneity in different geological settings on the pseudofunctions. A scaling-up system was defined and displacement calculations were made over a range of mobility ratios, viscosity/capillary ratios, and vis-cosity/gravity ratios for three geological types. A comparison othe results shows the effect of the different heterogeneities on displacements in various fluid-flow regimes. Fluid-flow regimes for each geological description are given where the scaling-up process is not required to give a good approximation of the displacement in the coarse grid.

This paper discusses the application of non-radioactive gas tracer in the two off-shore fields Gullfaks and Sleipner at the Norwegian shelf of the North Sea. The tracers applied are perfluorodimethylcyclobutane (PDMCB), perfluoromethylcyclopentane (PMCP), perfluoromethylcyclohexane (PMCH), 1,3 -perfluorodimethylcyclohexane (1,3 - PDMCH) and sulphur hexafluoride (SF6). The Gullfaks field consists of a complex reservoir with oil production from different formations. The field is laterally divided into nearly 40 fault blocks with varying degrees of communication. The main production strategy is pressure maintenance above bubble point by water injection. A WAG pilot was started in spring 1991. To improve evaluation of the pilot it was decided to inject tracers in the gas phase early in the first two gas injection periods. Production from the Sleipner field was started in August 1993. Reinjection of gas started in April 1994 and the first tracer, PDMCB, was injected in June 1994. The purpose of this injection was to investigate the travel time of reinjected gas and to monitor the reservoir performance. Samples of oil and gas were collected from the separator and analysed by gas chromatography (GC) connected to an electron capture detector (ECD). Sampling continued throughout the pilot period to establish the tracer production profile. The tracer compounds have a somewhat higher partitioning to the oil phase than methane, causing a minor retention of the tracer with respect to the average methane gas velocity in the reservoir. The tracer results have given valuable contributions to the interpretation of the WAG pilot mechanism and communication in the fields. Introduction Tracer technology has for many years been applied as a tool to improve reservoir description. According to literature the most widely applied gas tracers have been tritiated methane and 85Kr. However, since 1991 perfluorocarbon (PFC) tracer technology has been growing and is today applied in several of the most important fields in the North Sea. In addition to the PFC, sulphur hexafluoride has also shown excellent field tracer properties. A gas tracer program was started in the Gullfaks field in 1991. Since then five PFC tracers and SF6 have been injected in different wells. Preliminary results from these tracer studies were published by Ljosland et. al in 1993. In two of the wells, where WAG programs were performed, different tracers were applied in two subsequent gas injection periods to monitor the differences in gas movement after water had been injected. The tracer program at Sleipner was started in 1994. The tracers applied in this field are perfluorodimethylcyclobutane (PDMCB), perfluoromethylcyclopentane (PMCP). perfluoromethylcyclohexane (PMCH), and sulphur hexafluoride (SF6). The PFC tracers are all liquids at standard (ambient) conditions (see Table 1). The tracers were injected by high-pressure pumps directly into the main injection gas line at a rate of approximately 300 ml/min. The amount of PFC tracers injected in each well were in the range of 10 kg to 100 kg. corresponding to 6-60 1. Gas samples from production were collected in pressure cylinders and sent to the Tracer laboratories, Institute for Energy Technology (IFE), for analysis. The samples were primarily taken from the test separator at a pressure of approximately 70 bar. Due to limited capacity on the test separators, some samples were collected directly from the main separator or from the production flowline. Tracer Evaluation Perfluorocarbons (PFC) are hydrocarbons in which all hydrogen atoms are substituted with fluorine atoms. The general formula of the molecules is CxFy. The PFC tracer technology is now well established as a tool in atmospheric transport studies (3), in house ventilation examinations (4) and even in groundwater (5) and marine (6) tracing and water mixing processes (7). For use in water, an emulsion technique is needed due to very low direct solubility. The success of the PFC compounds is mainly due to chemical inertness, high thermal stability and high detectability by gas chromatography with an electron capture detector (GC/ECD). P. 675

SPE Members Abstract The process of injecting gas into a gas condensate reservoir during production is vital to maintain the reservoir pressure so that the heavy hydrocarbon fractions will be recovered. One would like to inject a gas into the reservoir that is cheaper than methane, but recent one-dimensional studies have shown that the injection of nitrogen into gas condensate at reservoir conditions will result in the loss of much of the condensate liquid. This is a result from the liquid dropping out of the gas phase when nitrogen mixes with the condensate. A solution to this situation is the initial injection of a slug of methane (or dry gas) followed by the injection of nitrogen for pressure maintenance. If the methane slug is large enough it will separate the nitrogen from the condensate and the liquid recovery will be high. The physical processes that tend to destroy the integrity of the methane slug are mixing due to rock heterogeneity, fluid fingering, and bypassing. This paper studies the two step injection process numerically with a three-dimensional EOS compositional simulator. The gases are injected into a heterogeneous quarter five spot. The recovery of liquid condensate is studied as a function of the composition of the injection gas, the methane slug size, and the magnitude of the permeability variations (heterogeneities) of the porous media. A fine grid involving 8,000 blocks is used to allow the proper description of the heterogeneities and to keep numerical dispersion, which simulates sub-grid block dispersion, at a reasonable level. Monte Carlo simulations are performed on realizations of reservoirs. The results show that the heterogeneities allow the nitrogen to mix with the condensate when the methane slug is small (5% to 10% of a porevolume) but the incremental recovery over the porevolume) but the incremental recovery over the injection of nitrogen is large enough to pay for the cost of the methane. Economics are given to allow one to size a methane slug for a real heterogeneous reservoir so as to maximize the profit of the project. project. Introduction The recovery of liquid hydrocarbons from a gas condensate reservoir is dependent upon maintaining as much of the reservoir as possible as a single phase gas. To accomplish this a fluid must be injected into the reservoir as condensate is produced to replace the reservoir volume, maintaining the reservoir pressure above the dew point pressure, and to displace the condensate towards the producing wells. The obvious choice of injecting dry separator gas (basically methane) plus some make-up gas (usually also methane) has both positive and negative aspects. On the positive side, combining methane with most gas condensates has only a small effect on the mixture's dew point. Thus, no liquid falls out. On the negative side, the injected methane is very expensive since it is not available for sales. A alternate choice is the injection of an inexpensive, inert gas, such as nitrogen. Previous experimental displacements with nitrogen Previous experimental displacements with nitrogen and a gas condensate in a slim tube have shown that liquid recoveries are as high as in displacements with methane, that is, of the order of 98%. However, in a numerical study, Kossack et al have shown that at field scale Peclet Numbers the increased mixing between the nitrogen and the condensate would cause a loss of 30 to 40% of the liquid as compared to a displacement with methane. Their simulations were one-dimensional, and thus, did not include areal sweep, gravity segregation, or viscous fingering. Their results did show that injecting a mixture of nitrogen and methane would increase the recovery over that of pure nitrogen. P. 19

The Nong Yao Field in the G11/48 concession is operated by Mubadala Petroleum on behalf of the other concessionaires KrisEnergy and Palang Sophon Limited. Nong Yao recently commenced production following a successful development drilling campaign, which was extremely challenging due to subsurface uncertainties. The subsurface team adopted an innovative method of well sequencing and optimization of targets, such that every well drilled is used to de-risk other wells, in order to avoid costly additional appraisal drilling. The key methodology involved a deep understanding of the exploration and appraisal data gaps and as a result the uncertainties / limitations of the static and dynamic models. A field development plan was developed that could achieve additional appraisal objectives, and in doing so, de-risk other wells as the development was executed. Uncertainties that the team sought to mitigate included structural uncertainty (due to shallow gas effects), fluid contacts and fluid type uncertainty, sand distribution and connectivity uncertainty and also uncertainty in the aquifer extent and degree of pressure support expected. This information was gathered by planning deeper high deviation development wells with complex 3D trajectories, which could intersect multiple reservoir sands and provide the formation evaluation and well landing points for later horizontal development wells in shallower reservoirs. Achieving appraisal objectives while drilling both in the static and dynamic sense, helped in optimizing well locations and led to the cancellation of multiple water injection wells, which were not required as drilling indicated better aquifer and pressure support than initially expected. This led to substantial savings in well costs and enabled rig slots to be utilized for production wells rather than unnecessary injection wells. Key technologies were used to achieve appraisal objectives. A high build rate hybrid RSS tool was used to deliver complex 3D well profiles and land wells above oil-water contacts while maintaining high ROP and wellbore quality. The deep resistivity distance to boundary LWD tool ensured horizontal production wells stayed in the reservoir sands and also helped to map the top and extent of structures, improving reserves calculations and reservoir simulation. In key wells the use of the ultra-deep resistivity tool for reservoir mapping combined with the LWD near-bit triple combo, helped in mapping the reservoir prior to entering it, eliminating the requirement for separate pilot wells. The impact was that more marginal oil pools could be developed with a higher degree of confidence. The clear value of these innovations was a reduced overall development cost and wells better placed for recovery and production. With lower development costs, more reservoirs of this nature in the Gulf of Thailand can become viable to develop, which has a significant impact on the future of Thailand's oil and gas industry.

TX 75083-3836, U.S.A., fax +1-972-952-9435 Pru Krathiam (PKM) is a small onshore, unconsolidated sandstone reservoir in Thailand containing medium heavy oil with viscosity of approximately 50 cp. Fluvial channels supplied sediments to form mouth bar sands in lake with sand thickness of 1 to 3 meters. In its 25 years of natural depletion, the field has achieved merely 1.7% recovery factor. The difficulty in production has been attributed to aquifer support combined with unfavorable mobility, and sand production. Secondary and tertiary recovery methods have been investigated, with the assumption that sufficient sand-control could be implemented. Basic EOR screening reveals that thermal and chemical methods could be appropriate for this challenging field, in addition to infill drilling. Further investigation by means of a history-matched full-field reservoir simulation model indicates that chemical flooding has the advantage over cyclic steam stimulation (CSS) in this type of reservoir and reservoir fluids. Polymer flooding using high molecular weight polyacrylamide gives significant recovery improvement. Its implementation will give an extra benefit to the field which has high initial water cut as polymer solution contacts the unswept regions of the reservoir. The oil recovery appears relatively insensitive to rock-polymer properties, i.e. adsorption, inaccessible pore volume, and residual resistant factor. Further study shows that adding alkaline and surfactant can increase oil recovery beyond polymer flooding. Generic properties of oil/water/ASP system e.g. interfacial tension and surfactant adsorption were used. ASP flooding performance seems sensitive to these properties, so extra care must be taken when designing the process. The fundamental constraint of polymer flooding and ASP flooding operation is the cost of implementation. CSS, on the other hand, still faces up severe problems with reservoir heterogeneities and high initial water saturation. Reservoir heterogeneities cause steam to disperse unevenly, leading to poor heat distribution. High water saturation results in much of the heat being absorbed by water. Mobility improvement by viscosity reduction is small for medium heavy oil and is slightly overcome by the effect of steam condensation. IntroductionPru Krathiam (PKM) is one of the fault-bounded dip closures located on the eastern flank of Phitsanulok Basin. The discovery well, PKM-A01, encountered viscous oil with 17-19 o API in Lan Krabu formation. Lan Krabu formation was deposited in the fluvio-lacustrine environment: fluvial sediments were transported from the east, and were deposited as mouth bar sands in the lake to the west. Evidences from grain size distribution and fossil indication match the notable characteristics of fluviolacustrine sediments, which are low energy aqueous deposition and the absence of marine fauna. In some areas, features such as levee, back swamp, coal and rootlets can be found. These are indications of shallow lacustrine deposits with frequent variations in the water...